Evolution Petroleum Corporation (EPM) Q2 2014 Earnings Report, Transcript and Summary

Good morning, and welcome to the Evolution Petroleum Corporation's Second Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Sterling McDonald, Chief Financial Officer. Please go ahead.

Good morning, and thank you for listening to Evolution Petroleum's conference call to discuss results for the quarter ended December 31, 2013, our second quarter of fiscal 2014. I am Sterling McDonald, and I'm the CFO of Evolution Petroleum. With me today are Robert Herlin, our CEO; Randy Keys, our incoming CFO; and Daryl Mazzanti, our VP of Operations. Actually, no, Daryl -- Daryl's not here, okay. Before we begin, let us cover the basics. If you'd like to be on the company's e-mail distribution list to receive future news, please see the contact information on our news release. If you wish to listen to a replay of today's call that will be available shortly by going to the company's website at www.evolutionpetroleum.com, or via recorded telephone replay until February 21, 2014. The necessary information can be found in the earnings release. Please note that any statements and information provided today are time-sensitive and may not be accurate at a later date. Our discussion today may contain forward-looking statements that are based on management's beliefs and assumptions that are based on currently available information. We can give no assurance that such forward-looking statements will prove to be correct, as they are subject to risks and uncertainties that are listed and described in our filings with the SEC. Actual results may differ materially from those expected. Our discussion may also include discussions of probable, possible or potential reserves recovery. Such unproven estimates are more speculative than proven reserves. We will begin our comments about our results for the year and quarter and then go to questions. Bob, would you take over?

Sure. Thanks, Sterling. And just to start with, I'd like to welcome Randy Keys to the Evolution team as he's going to be our CFO going forward following Sterling's upcoming retirement. Randy brings us a wealth of experience, not only in oil and gas, public accounting and finance but in oil field services. And we're counting on him to help grow our GARP business, as well as the -- continue being strong steward of our highly valuable Delhi asset. I also like for you to join me in thanking Sterling for his 10 years of outstanding service in growing Evolution from the original 2-person concept with only $1 million of equity and no assets -- no other assets, to where it is today, a sound and growing $400 million market cap public company with no debt. We certainly wish him the best in his pursuit of fly fishing, golf and mountain living. Back to the business end. Since detailed numbers are readily available to everyone in the news release that went out last night, we do have a number of specific topics to cover and I'm going to focus my remarks on key overall results of operations and nonrecurring items. Sterling will come back with additional commentary, and then I think Randy's going to add a few words, and then we'll take your questions. To start with, I want to remind everyone that we disclosed last November that we were starting a restructuring plan, a strategic plan that included staff reduction, as well as a refocus. And in nearly January, we further disclosed that we anticipated a nonrecurring charge of about $2 million to carry out debt restructuring. Our results for the current quarter that we announced last night reflect that nonrecurring charge of $2.1 million. And that includes several items, such as severance for the effective employees, costs related to a large exercise of most of our outstanding stock options and warrant. And I would like to note the specific impact to these important and strategic changes. First, we reduced staff by 27% and this will lead to -- or led to an annual overhead going forward that's been reduced by about $1.4 million per year. We've further reduced outstanding options and warrants from 4.8 million shares to less than 400,000 shares currently. Including subsequent exercises, employees have paid the company some $2.8 million of cash out of their pocket as part of these exercises. Now these exercises further generated over $31 million of current and future tax deductions that do not run through our income statement but they will reduce current and future tax payment by some $10.5 million based on the current statutory tax rate. Furthermore, we began distributing a portion of our free cash flow from operations to our common shareholders. Now of course, the downside to all this is that we did have this $2.1 million nonrecurring charge to earnings, and we expect to take a smaller $700,000 charge nonrecurring in the third quarter, which reflects Sterling's retirement dollars or roughly $0.02 a share. Our results were impacted by a number of other items. Production, our core assets at Delhi, it was up 6% over the prior quarter, but it's still being heavily impacted by the environmental events of last June. Oil prices were 12% lower than the previous quarter, although they have rebounded since in January. But also we've been able to cut our lease operating cost by almost half. Let's go to some specific projects. The operator of Delhi, which is a subsidiary of Denbury, announced the CO2 injection was resumed during current quarter in a portion of the field adjacent to the area being remediated. Since injection, that area was suspended from mid-June through November. While production was continued, recovery of most of the production rate decline may be extended. We have seen some improvement in total production but we believe that will be more due to development expenditures in late 2012, early 2013 and not due to the increase of CO2 injections. Gross production did average 6,264 barrels a day for the quarter. Like I said earlier, a 6% increase over the prior quarter. But oil prices there did decline. In a further positive note, the operator disclosed their intention to install a gas processor sooner than we had projected in our 2013 reserves support and for a fuller range of NGL recovery. Our 2013 reserves report projects that peak production at Delhi -- gross production, will reach about 15,000 barrels of oil equivalent per day by 2017. About 1/6 of that is from gas and gas liquids. And we also disclosed previously that we're in a dispute with Denbury as to the applicability of their 2006 indemnity of us regarding environmental liabilities. That dispute has not been resolved and subsequently, we were forced to file a lawsuit against them in December, seeking a declaratory judgment enforcing the 2006 agreement. That lawsuit includes both indemnity and damages from other breaches of the agreement. The primary effect of this litigation, however, is just really to determine when in 2014 that our working interest reversion will occur. We made progress on other fronts in our GARP business. We recently announced that we finally entered into an agreement with a large operator and getting steel in Central Texas, to install GARP on up to 10 wells that we believe are solid candidates. In return for providing use of the technology, overseeing the installation and paying for a portion of the cost of the installation, we will earn a fee equal to 25% of the total net profits from each well for likely installed technology. This agreement further allows for the addition of additional wells and we have identified hundreds of candidates to this customer's portfolio. The first installation should begin in our third quarter, fiscal '14. As an additional milestone, we did, as I mentioned earlier, hire Randy, not only as our CFO, but as our Executive VP of NGS Technologies, which is a subsidiary that operates our GARP business. And that should help move that business forward, Randy has substantial experience within the oilfield service industry through his work at Core Labs, 3DX and Flotek. In our non-core assets, we divide -- divested the last of our non-GARP producing properties in Texas with the sale of Lopez Field assets in December. We've initiated the test in Mississippian Lime's structural high by plugging most of the lateral on our Sneath well and producing from the last 1/3 of the lateral that penetrates the structural high. The well went on production early January, and we expect sufficient de-pressuring to occur by March to provide additional information as to this potential. We really don't expect to have any further CapEx in this project for fiscal 2014, and we are looking at strategic alternatives for that asset. Going forward, our CapEx in the remainder of fiscal '14, as well as productions and financial results, are heavily dependent upon when our work interest reversion occurs at Delhi. Financially, we're retaining considerable liquidity to allow us flexibility to meet our needs. With that, Sterling will now give you a little more background.

Thanks, Bob. Well, there's a lot running through our financial statements this period with the restructuring, and some of it's complicated especially on the tax side. So I won't try to anticipate your questions so that we can have more time for Q&A. As for the restart -- restructuring, I am very pleased with the strides that have been made in execution in a relatively short period of time, and the financial rewards that our shareholders have already realized. Management recognized Evolution's maturation going from only a deep discount play to possessing growth opportunities at Delhi and our GARP initiative, exercising its income distribution capabilities borne out of our high capital efficiency and still blending in a discounted net asset value play. Looking forward, Evolution has a rock solid balance sheet, $30 million of liquidity, no debt, safety and growth for cash flow, production in PV-10 at Delhi, and an opportunity to again raise left-for-dead resources back in the economic production with GARP much as we did at Delhi. I hope our present and prospective shareholders appreciate the clear and visible path that Evolution possesses to increase dividend distributions to its shareholders, not only from Delhi but with similar high capital efficiency available to us from GARP. But before I sign off, I'd like to thank Bob and the board for their leadership in allowing me this fantastically profitable run; Daryl Mazzanti, for his vision, practical engineering and tenacity that he's applied in helping us get Delhi into a CO2 play, 2-plus years of missionary work to bring the NGL plant and natural gas streams into the forefront for development at Delhi and bringing GARP ROI. I'd like to thank David Joe for his 9 years of loyal service and quiet determination as our Controller and Corporate Secretary; Brad Schultz [ph] for keeping the SEC filings going; and Cindy Sullivan for keeping the office, Bob and me between the ditches and not in them; and Kimberly [ph] for greeting you with a smile on the phone or in person, always. Oh, yes, and the observations from our shareholders and analysts have been greatly appreciated in the lightning. I only know some of you that post on the message boards. And it's been hard not to respond at times, but Bob Miller [ph] has certainly kept the record straight, and Ralph [ph] has been an energetic supporter. Then there's the big boss, my wife, Risa [ph], who I'd like to thank for her support and emotional perspective on our business. I'd also like to thank Randy Keys, your incoming CFO, for taking the financial administration and GARP development reins here at Evolution. I've run across Randy from time to time in the oil and gas and financial communities here in Houston, and having worked with him here over the last 10 days, I'm pleased tell you, he's solid. By way of introduction, Randy grew up in Midland Texas. Like Tulsa where I came from, it's a good place to learn about oil and gas at the dinner table. Randy began his career in public accounting with Peat Marwick at KPMG after graduating with honors from the University of Texas and posting the highest score in total in the CPA exam in Texas in 1980. In addition to very deep accounting and operational knowledge for oil and gas exploration and production he has a command of SEC rules: he's raised money in public and private markets; he has treasury background and oilfield service experience that will be valuable for the further commercialization of GARP. To this, he has an outgoing personality and an entrepreneurial bent. And on this last point, Randy and I both share launching our own startups before coming to Evolution. So Randy, would you say a few words?

Well, thank you very much, Sterling. I'm very pleased to join the Evolution team. The company is very well-positioned financially with large cash balance and no debt and it has an excellent core asset in the Delhi Field, with both near-term and long-term growth potential. Of particular interest to me is the opportunity to play a key role in the continuing rollout of our GARP Gas Assisted Rod Pump technology. It has the potential to make a significant impact on Evolution, and will benefit the industry by extending the lives of later-stage well and associated reserves. I look forward to being a part of the future of Evolution as it embarks on this new endeavor, and I am very pleased to be here. Thank you.

Thanks, Randy. I think it's evident that your management team is being very proactive in delivering value to our shareholders, and we're doing this by beginning to distribute a portion of cash flow and the excess of CapEx needs by continuing to efficiently grow our asset value. We can get a core benefit of having a substantial management stake in the ownership. The ending of the remediation work at Delhi and production response development expenditures from 2012 to 2013 should resolve in resumption of strong performance and production growth at Delhi. Reduction in overhead should also contribute strong results going forward, followed by our work interest reversion that should dramatically increase revenues earning some cash flow. Therefore, I think I can say with confidence that we are fully executing our strategy for the benefit of shareholders. And with that, we're ready to take some questions. So operator, please open the line.

[Operator Instructions] Our first question comes from Joel Musante at Euro Pacific Capital.

Bob, Sterling, welcome, Randy. Sterling, congratulations. The fly fishing, golf and mountain living sounds a lot better than equity research. Just I had a few questions just on Delhi. Just trying to get a sense for when reversion may occur. And I know you guys are in litigation, so maybe we can work around that. And as far as where you stand right now on how much of the payback amount has already been paid back, where are you at -- at last count?

Well, that's kind of a fluid question. If you look at it from our perspective, in which case we believe that our 2006 indemnity coverage from Denbury means that we shouldn't bear any cost to this environmental event, then remediation should have already occurred a matter of months ago sometime in the middle of the fall. Denbury is obviously making -- taking position the that there is no indemnity or -- I shouldn't quite say that, they're saying they're indemnifying us for they have the right to charge us for the cost of indemnity. I don't want to get into the details of this, but they're claiming that reversion isn't likely to occur until sometime the fall of 2014. So I think that kind of gives you -- yes, before insurance. Obviously, insurance reimbursement is going to substantially change the payout date or the effective date of it. The only question is when those reimbursements are going to be made. If you factor in, so say, 50% coverage then that will push reversion into late spring, early summer. So it's really hard to say. There's a pretty wide swing of possibilities. Obviously, we feel extremely strong in our position or we wouldn't have gone to the course we've taken. I really can't give you any better numbers than that.

Okay, all right. Well, that does help. So...

Joel, can you speak up?

Yes, I'm sorry. Where would the -- where was the production at, at last -- well, do you have a more recent number than just a quarterly production?

Well, the numbers that we have -- as you probably imagine, our communications with Denbury may not quite what they used to be at the moment. I would say that production -- last week production numbers we have are probably similar to what we reported for the quarter average. And that would be sometime in the November, December timeframe. So at the moment, we all think or we don't know that production is higher than that. They reported that CO2 injection was restarted in the area of the field close to the area of this field. But that is going to take a while to have any impact on production, because -- I guess I need to go a little more in the depth on this. Injection in the field continue -- or most of the field has continued throughout this whole timeframe. It was a portion of the field that they stopped injections of CO2 and -- but kept producing the wells in order to de-pressure the area, the reservoir close to the blowout -- the underground blowout. They have, I think, for about 5 or 6 months, they had continuous production in that area without any injection of CO2. So as you can imagine, that depleted a lot of the CO2 in that portion of the reservoir. And so now to -- they restarted just recently, I think it's in December, putting in CO2 back in that portion of the field and it's going to take a period of time for the reservoir to re-pressure before that area will begin to restore production back closer to where it was before all this happened. The rest of the field is continuing to produce as normal. And then part of the production increase that we seen recently, we believe is really more related to all the CapEx that was done at the end of 2012 and early '13 before all this happened in June. So we have the small increases in that regard, but we're -- we have not yet, we don't think, seen any restoration, production from the spill event itself.

Okay, are they at the same level of injection that they were prior to the release?

Not to our knowledge.

Okay.

And keep in mind that information we get is pretty stale, so I can't tell you what they've been doing in January, and obviously, not February. And we have December -- we have some December numbers, which don't yet really reflect significant changes in injection. What we have there is what they publicly stated at this point in time.

But injections have been off, the best we can tell. We don't have the injection, I mean, the -- excuse me, we don't have the purchase numbers for volumes. We do have the purchase numbers for expense and the -- it looks like the new CO2 expense came down quite a bit right after the event, maybe by 1/2 or more.

Obviously, that is a positive in extent that those purchases, obviously, aren't being charged. Our purchase expense is way down as well, and so the costs of operation are way down. Therefore, the payout account is not impacted as greatly by LOEs as it was before to offset some of the loss of production in revenue.

And also, probably tends to not have as much production response, right, Bob? As you pull back on the CO2 drive. But again, we're only inferring that from the CO2 expenses that are reported to us. Obviously, that varies with the price of oil but the price of oil hasn't been, in the last 6 or 8 months, not been all that volatile. So we think that the expense having, kind of have, or a little bit more is probably pretty indicative of how much new CO2 is being injected. But we did notice in December that the number came up a little bit. So it's inferential, but it looks like injections are starting to move back up.

Okay, all right. Just on GARP, how fast do you think you'll -- your first well, I think, you said is -- will be spud this -- or not spud. Your first installation will be this quarter, the third quarter, right?

It's correct. The agreement really calls for 2 kinds [ph] of well, the first 5, the second 5. In the process that we put together the development plan, which is basically the course, or schedule of work to be done for each well. We won't be the operator. The operator is our -- is the counter-party to the agreement. But we are setting up all the procedures, all the vendors and so forth. So I suspect that we'll get the first 5 done fairly quickly. And I suspect that the counter-party is going to want to watch that for a month or so. But we will be moving as quickly as we can, and it won't be so much sequential, and we'll try to as much parallel as we can. Our goal is to get all 10 done as quickly as possible so that we can demonstrate the validity of the benefit of the technology, and move on to start installing additional wells, as well as to use this as marketing information to other companies to show the benefit. But as quickly as we can, I'm hopeful that we can get all 10 done before the end of fiscal year, but since we don't have complete control over that, I can't guarantee that's going to happen. Certainly, we will do everything in our power to make it happen. By June 30, have all 10 in play.

Will they watch the first 5 and see how durable they are or do you think they'll just let you install all 10 before...

No, there is a time element in a sense that we can propose the development plan. They have a certain timeframe, they have to respond in terms of approving the plan and so forth, and the requirement to not do the second 5 is a pretty stiff test. I mean, you have to show the first 5 are uneconomic, and that this is pretty farfetched at this point in time. So I suspect that as long as the first 5 are demonstrating reasonable expectations, then there's no reason to believe that they won't want to go with the other 5 and keep going on.

Okay. Is there any reason why you can't tell us who the operator is?

Yes. They asked us to not use their name. That's the only reason.

All right. Is it public or private...

It is a public company. It's a very large operator, very significant presence in horizontal wells and many, many fields. And it is someone that we have worked with in the past. And their name starts with...

Okay. Are you -- as far as getting any contracts outside of Giddings, are you making any headway there?

Well, that's one of the reasons we brought Randy on board, and I have great confidence he's going to bring contracts -- rapid order this calendar year, but I think I will give him at least 1 month or 2 before I start expecting to see paperwork. I'm just -- I'm putting a little pressure because he's sitting across the table. But our key right now in the business is to provide many examples of why and how GARP works. And the more examples we have, I think, the easier a sell it is. We are getting much more traction, industries starting to take more notice. We're having more and more groups that are -- or are asking us to come and present at conferences, papers, articles. We're doing workshops for engineers. So we're feeling a lot better about the traction. And the charge I've given to Randy and to Daryl is that I want NGS Technologies, which is the subsidiary that markets GARP, to be a functional stand-alone company of its own right within this calendar year. And so that's where we're trying to get to, and I fully expect that we'll get there.

Okay and on the LOE, with the sale of the South Texas assets, do you expect LOE to come down even further?

Well, not really. It'll come down more because the last quarter, it still had, what, 2.5 months of operations in South Texas. And so absolutely, we'll drop the expense. From the flip side, we will -- we're not going to take that back. We're not really going to take operating expense on the GARP for us because of net profit fee. So yes, I suspect that we'll see LOE continue to climb in the next quarter. We'll obviously see significant change, I would think.

Well, that kind of depends on something that we discussed here internally as to whether the net profit interest is going to be booked, net or gross. So if we booked it net, it'd be like in orange [ph]. If we book it gross, we would flip the revenue and our share of revenue and our share of expense. And I don't know that we -- maybe you've made that decision, Bob but...

Well, we haven't made that decision. We have different options that we can look at, and accounting literature is evenly split on how you do it. So if we go net route, then you'll see LOE go down. If you see a growth calculation, then you're going to probably not see it go down it'll probably be flat or so forth, and overtime, it'll increase.

But one of the things I'm encouraged with is, in this particular type of risk sharing that if we may go other directions in the future, or the company may, but in this type of risk sharing, the operator's been able to -- because we've got the assignment of the well out of the way, which is what we were doing in the beginning where we're taking working interest, that makes it a lot easier for the operator, especially where he has joined interest partners -- working interest partners to not have to go to them to make assignments, wellbores make assignments of oil and gas, mineral oil interest, et cetera. And it gives the operator, we believe, a lot more control. And at the same time, the 25% number is kind of an interesting number to go with because in our business, deals are traded on 1/3 for ¼ [ph], which intimates [ph] 25% carried. They also have backings after payout, 25% is not an uncommon number. So we may be kind of getting our sites into a slot, but more easily so. And as Bob says, we're getting a lot more activity and interest in the community right now, so.

Okay, all right, good deal. One last question on the -- so your -- on a per-BOE basis, your LOE came in around 4 -- or, I think, $4.77. And that represented about 9% or 10% of your production that has a working interest component. So if you scale that up, it would be about $47 for those operations on a BOE basis?

Right.

So if you take out those other -- those South Texas wells, I'm just wondering where that kind of falls in place.

We don't have the exact breakdown but the biggest chunk of that LOE is probably associated with South Texas. We weren't really getting much production down there in the last 6 months. We're in the process of getting that lawsuit down there resolved. We're in the process of getting the property sold. We're really -- We're not focused on maximizing production per se, but we were trying to finish up some work, make sure the wells are online and productive. So I'm not sure that, that LOE per barrel, net of Delhi, is really instructive at this point. Going forward, I think it will be very instructive. And one of the things that I hope to start doing is having separate line items on the NGS Technology group to demonstrate the economics of GARP going forward. But I don't think that it really is informative at this point based on the last quarter numbers.

[Operator Instructions] And our next question comes from Jeff Grampp at Northland Capital Markets.

So just kind of wanted to maybe touch on this lawsuit a little bit, and maybe any color you guys can provide in terms of timing and how long it's going to take. I know it's still relatively early, but in your end can we potentially see reversion at Delhi be delayed as a result of this lawsuit, or this is somewhat of a separate event in that regard?

I would think that they're somewhat independent in the sense that we have filed a litigation or lawsuit against them for things that they're doing today. So I'm not too sure that I can really -- or should really talk much more than I have about the litigation. But I would say the 2 are independent at this point in time.

Okay, got it.

I think any litigation -- we're in the very early stages of it. And litigation is something that can take a long time to get resolved but the issue, as I said earlier, the issue is really about when reversion occurs during 2014. I don't see any basis for that reversion being extended because of litigation.

Got it, okay. And then on the tax side of things. I know you guys have a lot of moving parts there with these options, transactions, et cetera. But just trying to get a sense for maybe what the go-forward tax rate would be or what's a good number to look at in terms of an effective tax rate, maybe what portion of that would be deferred?

Okay, well, the tax rate that has been trued up to in this quarter is 40%, roughly. And what that -- the components of those are 34% federal; 8% Louisiana. But Louisiana allows the deduction for federal tax paid, and of course federal allows a deduction for Louisiana tax paid. That former one, the federal tax paid, so you're going to be 0 for a while. So in the Louisiana return, it won't generate a deduction. And in the federal return, we will have still a deduction for Louisiana. If there were federal taxes being paid, which should be after we burn through the $31 million of deductions that were created from stock compensation due to the exercises, then that rate would be 38% generally, and not 40%. And as you can see, neither of those rates are 34 plus 8, or 42. But I want to throw another element in here. Even though our tax rate's going up, our tax cash is -- our cash tax paid is going to go down. And the way the accounting rules work, unfortunately, is that all these deductions, this $31 million of deductions, they're called -- the term of art is unbenefited tax benefits. And that means that we will not be carrying those deductions through the P&L statement for financial reporting purposes, and therefore, we don't get a credit for those taxes not being paid. So when it comes time to pay the taxes, we run the provision like we normally would. We have an accounts taxes payable and we will be allowed to extinguish, if you will, that liability, wiping out the payable and then they're credit directly to equity. So still running through the income statements that runs directly to equity. It's unfortunate that you don't see the benefits of all that but the bottom line is, is that we're going to pay about $10.5 million less taxes than we otherwise would pay, overtime. It benefits us that $10.5 million of cash won't go out the door, and it benefits us that we will, over time, increase our book equity by the same amount. And I'm glad to take other questions if you have them on those points. And by the way, that only offsets current payables. It would not offset deferreds. Is that right, Rob? Okay.

Okay. So suffice to say the current cash portion of your taxes are going to be substantially reduced as you burn through that $10 million or so?

They're reduced to 0 up to, we get the $31 million of reductions, and then they will no longer be reduced.

We will continue to show tax expense, we just won't be paying it.

Got it. That helps a lot. And then last one...

I just want to add this. Once we burn through this, we will go back and have percentage depletion in excess to basis that will form a permanent tax difference to book, and that was what was driving our tax rate down in the last quarter, down to 25%, as we were starting to burn through those. And then all of a sudden, here we've got this new deduction and under the ordering rules, we take the deduction first. But the percentage depletion will continue to build and will be used later on, the reduced taxes and our book rates.

Okay, got it. It's helpful. And then last one, I guess, I just wanted to touch on the preferreds real quick. I know the call date's coming up on that. And if maybe you guys had determined anything on your end in terms of what you're going to do with that.

At this point in time, we have made no decision as to what we're going to do with the preferred. That will be something that we will be making recommendations to the Board sometime in the fourth fiscal quarter. But it is -- I can't tell you what that interest is going to be. And frankly, a lot of it will depend on what happens between now and then or later this year as to when reversion occurs, what CapEx we see coming up and so forth. One of the reasons we kept our liquidity so high is to make sure that we have sufficient flexibility. I mean, any CapEx need at Delhi, and we certainly don't want to give away that flexibility until we have alternatives to meet any potential needs. So at this point in time, I can't tell you what we're going to do.

Our next question comes from Chris McCampbell of Southwest Securities.

Not to beat a dead horse here but just in relationship to the reversion, your expectation is that this is a process of really just months and not so much this could stretch on into 2015, correct?

At this point, I have absolutely no basis to believe that reversion is going to be delayed into 2015. And many reasons, we believe it, will be sometime in the next 1 to 9 months. Or 0 to 9, or maybe a minus 1 to 9 months. Obviously, if we prevail in trial, which wouldn't happen, obviously, until next year, more than likely, we would still say reversion will occur this year so we might be getting a nice, fat check from Denbury to reimburse us for all those months that we should have reverted. And I'm being very pleased to go cash a check for, I don't know, $20 million? Some big number, whatever it might be.

Well, but in relationship to that, I mean, wouldn't it be in Denbury's best interest to go ahead and try to run the clocks since they just have to pay the money eventually anyway?

Well, there's damages that go into that. There's court costs, when we're asking for lots of damages here. So I would say no, it's not to in -- to their benefit. I mean, one of the things that they need to understand, which I don't want to get into that, I guess, but we're more than happy to start paying our share of the freight on CapEx. But we're not going to do that until reversion occurs. But there's still some CapEx left to finish off the development of the field. And there's no point in postponing that. I mean just hurts their economic interest of postponing development. So I feel hopeful, cautiously optimistic, I should say, that we'll get this resolved, a shorter trial. But if not, we have no problem with it going forward. We've demonstrated that in the past that we're going to defend our interest whatever it takes and so we'll continue to do that here.

Let me add to what Bob says about going to trial. I mean the parties are still talking, so -- but the court will move at its pace. So once we get deep in the court, I mean, you can settle things at any time, I suppose. But let's just say that the communication lines are not dead at the moment, and we're helpful to get this resolved sooner rather than later.

Sure. In relationship to the GARP, how many wells per quarter do you think you could start installing if the industry embraced it?

Our current capacity is 1 field superintendent can do about 4 installations a month, and we have 1 current superintendent on our payroll who's been doing this for us. So we could directly do as many as 45 or plus installations a year, and they would not take a tremendous effort to add a second superintendent out in the field to do these installations. So we have pretty high capacity. And obviously, the industry is drilling 3,000 or 4,000 horizontal wells every year. There's already a portfolio out there of tens of thousands of horizontal wells. And of course, GARP is applicable, not just horizontal wells, but also vertical wells. That's not -- every one of those, there has to be certain kind of well for GARP to work on. We're focused on the top 1 or 2 quartiles. It's for depletion job reservoirs that will inhibit liquid loading, either on oil well or a gas well. We typically are going to add 15% to 35% until it's already been produced. So obviously, if a well's a poor well, it's not going to be a candidate because we can't make a poor well into a good well. But we can take a good well and make it a better well, and that's really what we're trying to tell the industry and what we're demonstrating, I believe.

To the extent that there's a education process here, I'm happy to take it off-line with you all. But if it's a short answer, who would you say or what technology would you say you're competing against?

We don't really think that we have a direct competitor. We believe that GARP represents a more of a revolutionary change in our visual lift. The current competitors are really more evolutions of the existing technology, which is, you take your existing mechanical rod pump and maybe even figure a way to stick it a little further down the curb to handle the bend in the curb. Or maybe in a vertical well, it's -- you take that rod pump, and you have the ability to handle solids that won't get stuck, you pack it in, you lose a well. Or maybe it's taking a submersible pump that's capable of working in small fluid volumes. Those are the kinds of competition that we would say that we currently face. We don't see anyone currently that is really a revolutionary competitor for us. So it's really -- our previous competition is just educating industry as to how it works, why it works and why it's better and what the benefits are. And clearly, what we think is that we can add reserves to wells at a cost of no more than a couple of dollars per BOE. We can extend lives of wells from some 0 to 20-plus years. And therefore, we can hold leases for an extra 10, 20 years. We're very, very bullish and optimistic about the business. One of the things you need to know is that GARP does not benefit a well until the liquid loading issue arises. If you take a well that is still producing in good shape and put GARP on it, you're not going to see one bit of change. It's only when you have the liquid loading issue comes up, where the liquid level falls below the rod pump, or in the case of a gas well, where the liquids in the wells have risen to the point that gas can't make it through that liquid column, and production starts to rapidly fall off. That's when GARP works and is very demonstrable in terms of benefit. And what you do is you put GARP to production on the well back to where it was before the liquid loading issues grows. It isn't going to make a well -- for example, you might have a well that was making 15 barrels a day, liquid loading hit and it goes to 1 barrel a day. We put that well on with GARP then we get back to 15 barrels a day at a very low decline rate, maybe 3%, 4%, 5%. So we can have a lot of reserves but not at real high rates and so we're extending life by 10, 20 years.

How many wells do you think there are out there that potentially can benefit from GARP right now?

Eventually, of the current set of wells, there's thousands of horizontal wells that potentially could be candidates. We know there are already or many hundreds of wells getting to field, and the reason we plan on getting to -- that was the first field for horizontal drilling could be really widely applied, those back in the late '80s. And therefore, most of the wells there are starting to become mature. A lot of the newer plays, the Eagle Ford, the Bakken, Haynesville, Niobrara, Barnett, Marcellus, there's just too new. There's not enough wells that are good wells that are hitting that mature point where you have loading issues. Probably the closest one would be the Barnett. All those gas wells, they're now in their tail production. We're starting to hear a lot of stories about operators being very concerned that all of a sudden, they've gone from 3%, 4%, 5% decline to 30%, 40%, 50% decline because of the loading issues. And they're starting to, frankly, how we get our tail reserves because you're starting to have run of a BCF or so per well. That'd be a great application for GARP. So potentially, South and the West currently horizontal, many thousands of wells vertically by counting Permian. But those numbers will just continue to climb every year.

Lastly, you had a year-over-year decline and shares outstanding by about $1.8 million. Was that just associated with the exercise in some poor fashion? Or do you have a share repurchase plan that's active?

Well, we went -- before last November and the option exercise, we had a little over 28 million shares outstanding. We also had about $4.8 million options and warrants outstanding. Today, we're probably, what, 32.5 million shares outstanding, but less than 400,000 options left. So on a fully diluted basis, it's come down maybe 0.5 million total. That would be the only difference. What you're seeing is that just we've gone from a mix of outstanding shares plus large derivatives to really very few derivatives and mostly outstanding shares. And the result of that, though, is because of the exercises, with 0.5 million fewer shares, they're dilutive for the shareholders going forward because of those net exercise the occurred in November and January.

At this time, we show no further questions. I would like to turn the conference back over to Mr. Herlin for any closing remarks.

Thanks, again, to everyone. I appreciate your attendance this morning and your excellent questions. As you can see, this was a tough quarter for us to explain all the nuances. Clearly, it's a bump, but it's a bump that we knew about, and we told everybody about. It really has no impact whatsoever on our future performance results. So we're still extremely excited about our company and where we are and where we're going forward. We think we're well-positioned, and we're excited about the opportunities. We'll continue to see the dividends grow, we think. And feel free to give us a call, and we'll be more than happy to talk about the stuff we've talked about already and in the press release. So again, thank you, and I'll see you next quarter.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.